CA3116804A1 - System and method for operating downhole pump - Google Patents

Abstract

A method for acquiring data relating to the performance of a downhole pump, analyzing said data, and adjusting the operation of the downhole pump in response to the data, as required. The interior fluid pressure of a tubing string of a wellbore is measured using pressure sensors located on the tubing string at or near surface, and fault conditions associated with the operation of the pump can be detected from the surfacing tubing measurements, such as the presence of fluid pounding, a leaking standing valve, a leaking travelling valve, or gas interference. If a fault condition exists, the fault can be automatically reported to an operator such that pump operation can be adjusted to correct the fault, if possible, or the pump can be retrieved to surface for repair. A "pump pressure card" can be generated from the acquired pressure measurements showing surface tubing pressure vs. rod position.

Description

"System and Method for Operating Downhole Pump"
FIELD
[0001]
Embodiments herein relate to downhole pumps for use in oil and gas wells. In particular, embodiments herein relate to a system and method for detecting and addressing faults in the operation of downhole pumps by using arrangements of sensors at surface and measurements of surface tubing pressure.
BACKGROUND

[0002] Oil and gas production operations often use reciprocating pumps in the wellbore to produce hydrocarbons to surface from hydrocarbon reservoirs.
With reference to Fig. 1, such reciprocating pumps 10 typically comprise a plunger/piston 12 having a travelling valve 14 at a downhole end thereof and configured to reciprocate within the chamber of a pump barrel 16. A standing valve 18 is located at the bottom of the barrel 16. The fluid outlet of the barrel of the reciprocating pump is connected to the distal end of production tubing 8, such as coiled tubing (CT), and produces hydrocarbons to surface therethrough.
During pumping, the barrel 16 remains stationary in the wellbore W while the plunger 12 is connected to a pumpjack 4 at surface via a polish rod and a rod string 6 of a plurality of sucker rods extending downhole through the production tubing 8, the rod string 6 and plunger 12 being reciprocated uphole and downhole to produce hydrocarbons from the reservoir to surface. Such a pump is also known as a rod pump. During the upstroke, the travelling valve 14 remains closed and prevents accumulated fluid F thereabove from flowing back downhole therethrough, such that the fluid column in the production tubing 8 above the travelling valve 14 is displaced towards surface. The uphole movement of the travelling valve 14 within the barrel 16 creates a negative pressure therebelow in the barrel chamber that opens the standing valve 18, permitting fluid from the wellbore W to enter therethrough. During the downstroke, the standing valve 18 is closed due to the increase in fluid pressure in the barrel chamber 16 caused by the downhole movement of the plunger 12. Said increase in fluid pressure in the barrel 16 also opens the travelling valve 14, permitting fluid accumulated in the barrel chamber 16 to enter the plunger 12 and join with the fluid column F in the production tubing 8. After the plunger 12 reaches its bottommost position and begins a new upstroke, the travelling valve 14 closes once again to move the accumulated fluid column F towards surface, and the standing valve 18 opens once again to allow more fluid to enter the barrel from the wellbore W.

[0003]
Various problems can occur during downhole pump operation including, but not limited to, gas interference, fluid pound, fillage issues, standing valve leakage, travelling valve leakage, and the like. Detecting problems with downhole pump operation is important, as problems such as gas interference and valve leakage can result in inefficient production, and fluid pound or partial fillage can damage the pump and/or rod string.

[0004] Pump operation can be adjusted manually to respond to any detected problems. Pump jack controllers, or other controllers capable of monitoring and adjusting pump operations, can also be used to automatically adjust the operational parameters to remedy or mitigate problems, such as by adjusting the pump cycle speed.

[0005] The predominant method of analyzing pump performance is to measure the axial load on the rod string 6 at surface as it relates to the position of the pump plunger 12 in the pumping cycle for generating a load-versus-position plot known in the industry as a dynamometer card. Force and position measurements for the dynamometer card are typically made at the surface rather than at the downhole pump, as installing instruments to measure the force exerted at the remote and distant pump is impractical or expensive.
Specifically, rod load is measured at surface, and the position of the pump jack head can be used in place of pump plunger position. While measurements made directly at the downhole pump would be more desirable for the purposes of assessing pump performance, Applicant is not aware of any sensors that can be located at the downhole pump, as the pump is often located hundreds of meters underground. Therefore, to date, measurement instruments at surface are used to measure the axial forces on the rod string at surface and the data is used to generate a surface dynamometer card (SDC). The SDC can then be converted by the pump jack controller, or computer located on or off-site, into a downhole dynamometer card (DDC) using a conversion process called diagnostic analysis.
Rod force is indicative of downhole pump performance, but is complicated by mechanical problems that can mimic fluid-related problems in force measurements, and vice versa.

[0006] There exist many complex models for creating a DCC from an SDC. For example, a numerical algorithm for diagnosing pumping conditions for vertical wells was proposed by Gibbs in 1963 (see Gibbs, "Predicting the behavior of sucker-rod pumping systems. Journal of Petroleum Technology", 15(7):769-778, July 1963).

[0007] The calculation of DDCs can be computationally intensive, particularly for deviated wells, that is, wells having a wellbore that is not vertical.
In practice, many wellbores are at least slightly deviated due to defects in the drilling process. Moreover, the number of intentionally deviated wellbores, including horizontal wellbores, has steadily increased over the years. Such deviated wellbores require DDC-calculating models to account for phenomena such as three-dimensional vibrations of the rod string, friction between the rods/couplings and the production tubing, and the effect of gravity on a rod string that is partially supported by deviated sections of the wellbore. The use of such complex calculations to obtain DDCs poses a significant potential for errors, which can result in inaccurate DDCs and consequent misdiagnosis of pump performance. The use of complex models also limits the rate at which DDCs can be updated, and the relatively high computational load results in increased power consumption.

[0008] There remains a need for a more efficient and accurate method of acquiring and analyzing data regarding downhole pump performance that does not require the use of complex calculations and models, and with the outcome of better responding to pump conditions, all the while still permitting data to be measured at surface.
SUMMARY

[0009]
Generally, a method is provided for acquiring data relating to the performance of a downhole pump, analyzing said data, and adjusting the operation of the downhole pump in response to the data, as required. More specifically, methods disclosed herein relate to measuring the interior fluid pressure of a tubing string of a wellbore using pressure sensors located on the tubing string at or near surface, and determining from such pressure measurements whether a fault condition exists, such as the presence of fluid pounding, a leaking standing valve, a leaking travelling valve, or gas interference.
If a fault condition exists, the fault can be automatically reported to an operator such that pump operation can be adjusted to correct the fault, if possible, or the pump can be retrieved to surface for repair. In embodiments, a "pump pressure card" can be generated from the acquired pressure measurements showing surface tubing pressure vs. rod position. In embodiments, temperature measurements can also be taken in order to temperature-correct the pressure measurements obtained by the pressure sensors.

[0010] A
system for acquiring surface tubing pressure data for analyzing downhole pump performance is also provided, comprising one or more pressure sensors located on the tubing string and configured to measure pressure inside the tubing string. The pressure sensors are connected to a processor configured to sample and analyze pressure measurements from the pressure sensors to determine the presence of fault conditions in the measurements.

[0011] In embodiments, the pressure sensors have a sufficient sampling rate and resolution for obtaining surface tubing pressure measurements for analyzing downhole pump performance. Further, the acquired pressure data is temperature-indifferent or temperature-compensated/normalized.

[0012] Such a method and system for analyzing downhole pump performance and adjusting pumping operations is advantageous as it provides an accurate indication of the presence of common fault conditions derived from surface pressure measurements without requiring complex calculations and models to be applied to said surface measurements. Instead, the pressure measurements can be analyzed directly. As pressure travels uphole from the pump to surface at the speed of sound via the fluid inside the production tubing (approximately 1000 m/s), the analysis of surface tubing pressure allows for the acquisition of near real-time data regarding pump performance without the high computational power requirements associated with conventional systems.
Consequently, the system disclosed herein consumes power at a relatively low rate compared to conventional systems.

[0013] In a broad aspect, a method of operating a reciprocating downhole pump located in a wellbore and fluidly connected to equipment at surface via a tubing string for flowing well fluids to the surface is provided, comprising:
locating one or more pressure sensors on the tubing string at surface; obtaining surface tubing pressure measurements of the tubing string at surface at a sampling rate using the one or more pressure sensors; analyzing the pressure measurements indicative of pump performance; identifying the existence of one or more fault conditions from the pressure measurements; and reporting the existence of the fault condition.

[0014] In an embodiment, the method further comprises predetermining the effect of temperature on the pressure measurements obtained for each of the one or more sensors and correcting the pressure measurements obtained from the one or more pressure sensors to account for the effect of temperature thereon.

[0015] In an embodiment, the method further comprises locating one or more temperature sensors on the tubing string at surface, obtaining temperature measurements using the one or more temperature sensors, and correcting the pressure measurements obtained from the one or more pressure sensors using the temperature measurements obtained from the one or more temperature sensors.

[0016] In an embodiment, the one or more temperature sensors are positioned such that the temperature measurements are representative of the fluid adjacent the one or more pressure sensors.

[0017] In an embodiment, the sampling rate of the pressure measurements is at least six times a cycle rate of the downhole pump.

[0018] In an embodiment, the sampling rate of the pressure measurements is about 15 times the cycle rate of the downhole pump.

[0019] In an embodiment, the step of obtaining pressure measurements further comprises converting the pressure measurements from analog data to digital data at the one or more pressure sensors.

[0020] In an embodiment, the step of analyzing the pressure measurements further comprises generating a waveform of the pressure measurements over time.

[0021] In an embodiment, the one or more fault conditions comprises fluid pounding, leaking standing valve, leaking travelling valve, and gas interference.

[0022] In an embodiment, the step of automatically reporting the existence of the fault condition further comprises: reporting a fluid pounding fault condition if the pressure measurements drop rapidly after one or more pressure peaks of the pressure measurements; reporting a leaking standing valve fault condition if the pressure measurements are not within an expected low pressure range during a downstroke time segment of the pressure measurements; reporting a leaking travelling valve fault condition if the pressure measurements are not within an expected high pressure range during an upstroke time segment of the pressure measurements; and reporting a gas interference fault condition if the pressure measurements are not within an expected low pressure range and are substantially constant during a downstroke time segment of the pressure measurements.

[0023] In an embodiment, the step of obtaining pressure measurements further comprises increasing the sampling rate if the existence of one or more fault conditions is identified.

[0024] In an embodiment, the method further comprises: establishing position measurements related to a position of the reciprocating downhole pump;
and generating a pump pressure card using the pressure measurements and position measurements.

[0025] In an embodiment, the equipment at surface comprises a pump jack, and the position measurements are established from a position of the pump jack.

[0026] In an embodiment, the equipment at surface comprises a rod string connecting a pump jack to the downhole pump, wherein the position measurements are established from a position of the rod string.

[0027] In an embodiment, the method further comprises calculating a pump fillage index from a peak-to-peak pressure difference of the pressure measurements over a pump cycle and a rapid pressure drop difference between an end of an upstroke time segment of the pump cycle and a beginning of a downstroke time segment of the pump cycle.

[0028] In an embodiment, the method further comprises: establishing a peak-to-peak pressure difference of a pump cycle from the pressure measurements; establishing a rapid upstroke and downstroke pressure drop difference between an upstroke time segment and downstroke time segment of the pressure measurements; establishing a running average of a difference between an upstroke time segment and downstroke time segment of the pressure measurements for multiple pump cycles; and calculating a pump fillage index from the peak-to-peak pressure difference and the rapid upstroke and down stoke pressure drop difference.

[0029] In a broad aspect, a system for determining performance of a reciprocating downhole pump located in a wellbore and fluidly connected to equipment at surface configured to receive fluid delivered therefrom via a tubing string is provided, comprising: one or more pressure sensors positioned to obtain pressure measurements from within the tubing string at surface; and a processor configured to receive the pressure measurements from the one or more pressure sensors for sampling pressure data from the one or more pressure sensors at a sampling rate.

[0030] In an embodiment, the sampling rate is at least six times a cycle rate of the downhole pump.

[0031] In an embodiment, the sampling rate is at least 15 times a cycle rate of the downhole pump.

[0032] In an embodiment, the system further comprises a communications device operatively connected to the one or more pressure sensors and configured to receive the pressure measurements from the one or more pressure sensors and send said measurements to the processor.

[0033] In an embodiment, the system further comprises one or more temperature sensors positioned to obtain temperature measurements of the fluid flowing within the tubing string at surface.

[0034] In an embodiment, the one or more pressure sensors are silicon crystal piezoelectric sensors.

[0035] In an embodiment, the one or more pressure sensors are single crystal silicon crystal piezoelectric sensors.

[0036] In an embodiment, the one or more pressure sensors are capable of obtaining pressure measurements in increments of 1/220 from 0 to 1000 psi.
BRIEF DESCRIPTION OF THE DRAWINGS

[0037] Figure 1 is a schematic representation of a prior art pump jack system;

[0038] Figure 2 is a flow diagram of the transfer of energy in a pump jack system;

[0039] Figure 3A is a graphical depiction of pump jack position over time;

[0040] Figure 3B is a graphical depiction of pump plunger position over time;

[0041] Figure 3C is a graphical depiction of pump discharge pressure over time;

[0042] Figure 3D is a graphical depiction of surface tubing pressure over time;

[0043] Figure 4A is a graphical depiction of pump rod force and pump plunger displacement over time;

[0044] Figure 4B is a graphical depiction of pump discharge pressure and pump plunger velocity over time;

[0045] Figure 5A is a diagram of a downhole pump of a pump jack system at the end of the upstroke portion of its pumping cycle;

[0046] Figure 5B is a diagram of the downhole pump of Figure 5A at the beginning of the downstroke portion of its pumping cycle;

[0047] Figure 5C is a diagram of the downhole pump of Figure 5A at the end of the downstroke portion of its pumping cycle;

[0048] Figure 5D is a diagram of the downhole pump of Figure 5A at the beginning of the upstroke portion of its pumping cycle;

[0049] Figure 5E is a model pump pressure card depicting normal downhole pump operation;

[0050] Figure 6A is a graphical depiction of measurements of surface tubing pressure over time for a normally operating downhole pump;

[0051] Figure 6B is a graphical depiction of a sinusoidal estimate of surface tubing pressure from the measurements of Figure 6A, and a sinusoidal estimate of pump position;

[0052] Figure 6C is a pump pressure card based on the graphical depiction of Figure 6B;

[0053] Figure 7A is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump experiencing partial fillage or fluid pounding;

[0054] Figure 7B is a graphical depiction of a the measurements of surface tubing pressure of Figure 7A and a sinusoidal estimate of pump position;

[0055] Figure 7C is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump experiencing a more pronounced case of partial fillage or fluid pounding;

[0056] Figure 7D is a pump pressure card generated from the measurements of Figure 7C;

[0057] Figure 7E is a model pump pressure card for a downhole pump experiencing partial fillage or fluid pounding;

[0058] Figure 7F is a graphical illustration of a method of calculating pump fillage from a pump pressure card;

[0059] Figure 8A is a diagram depicting the standing valve of a downhole pump leaking during the downstroke of the pump cycle;

[0060] Figure 8B is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump with a leaking standing valve;

[0061] Figure 8C is a pump pressure card for a downhole pump with a leaking standing valve;

[0062] Figure 9A is a diagram depicting the travelling valve of a downhole pump leaking during the upstroke of the pump cycle;

[0063] Figure 9B is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump with a leaking travelling valve;

[0064] Figure 9C is a pump pressure card for a downhole pump with a leaking travelling valve;

[0065] Figure 10A is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump experiencing gas interference;

[0066] Figure 10B is a graphical depiction of measurements of surface tubing pressure over time for a downhole pump experiencing gas interference with a sinusoidal estimate of pump position;

[0067] Figure 10C is a diagram depicting the travelling valve of a downhole pump experiencing the effects of gas interference at various stages of the pump cycle;

[0068] Figure 10D is a graphical depiction of measurements of surface tubing pressure over one pump cycle for a downhole pump experiencing gas interference with a sinusoidal estimate of pump position; and

[0069] Figure 10E is a pump pressure card for a downhole pump experiencing gas interference.
DESCRIPTION

[0070]
Generally, an improved method of assessing downhole pump performance, and improving the operation thereof, is provided. The method comprises acquiring measurements of tubing string pressure at surface at a rate and resolution to sufficient discern the variations in pressure typically produced by the regular operation of the pump.

[0071]
Applicant has discovered that the use of surface tubing pressure measurements, meeting suitable data capture criteria, to evaluate downhole pump performance and diagnose malfunctions therewith provides an advantageous alternative to the conventional method of measuring rod load and pump jack position, generating an SDC, and calculating a DDC therefrom.
Namely, the use of surface tubing pressure measurements permits the evaluation of downhole pump performance directly from surface measurements without the use of complex calculations and modelling associated with calculating DDCs from SDCs.

[0072] With reference to Fig. 2A, embodiments of a method and system for evaluating downhole pump performance herein are described with reference to a pump jack system 2 for producing hydrocarbons from a wellbore W, the system 2 comprising a pump jack 4 located at surface connected to a rod string that extends downhole through production tubing 8 and is operatively connected to a downhole pump 10. The downhole pump comprises a plunger 12 having a travelling valve 14 that is housed within a barrel 16 having a standing valve 18.
The barrel 16 is fixed to a distal end of the production tubing 8 and the plunger 12 reciprocates within the barrel with the rod string 6.

Assessing Pump Function Using Tubing Pressure

[0073] The use of surface tubing pressure measurements P to assess downhole pump operation is based on the principle that energy in a system is conserved, and correlations between various forms of energy can be made by tracing the flow of energy, or energy chain, throughout the system.

[0074] With reference to Figs. 2A and 2B, the transfer of energy that takes place in the pump jack system 2 through the course of a typical pumping cycle is depicted. At an initial step 22, movement of the pump jack 4 provides kinetic energy to the system 2. The translational kinetic energy applied by the pump jack 4 at surface is transferred to the downhole pump 10 via the rod string 6 extending through the production tubing string 8 to the downhole pump 10. The input energy of this movement can be further broken down into two components: force 22a and displacement speed 22b. At step 23, movement of the pump jack 4 is transferred via the rod string 6 to movement of the pump plunger 12, which can also be broken down into force 23a an displacement speed 23b components. At step 24, the downhole pump 10 then converts this input energy in the form of rod force 23a and displacement speed 23b into a discharge pressure 24a and fluid flow 24b (the fluid being oil, water, and possibly gas from the hydrocarbon formation). The pressure 24a that is generated by the downhole pump 10 in turn travels towards the surface at the speed of sound through the fluid F in the tubing string 8, which acts as an energy conveyor, and is detectable as surface pressure 26 also having components of pressure 26a and flow 26b. The tubing string 8 is normally filled with fluid F such as water and/or oil and, as a result, the speed of sound travels faster than for a gas-filled condition. More particularly, the speed of sound through oil and water at typical temperatures and pressures in production operations is about 1000m/s, and fluctuates with changes in temperature and pressure. Therefore, even if the downhole pump 10 is located 1000 meters from surface, pressure changes occurring at the pump 10 will reach the surface and become measurable by a surface pressure measurement device 30 positioned to measure surface tubing pressure P in about one second.
Therefore, tubing pressure P measured at surface can be taken to be substantially representative of the discharge pressure Pd from the downhole pump, with a small time delay. Consequently, measurements of tubing pressure P obtained at surface contains useful, near real-time information as to how pump is performing. By analyzing surface tubing pressure P, a pump fault or malfunction can be identified quickly, and an alarm notifying the operator of the fault and requesting the proper response can be generated to remedy the situation. In embodiments, the pump jack controller can be configured to automatically respond to the generated alarm and take the necessary steps to remedy the detected fault.

[0075] As one part of the energy chain of Fig. 2B is the discharge pressure and flow generated by the downhole pump (which contains information regarding the pump's ability to produce hydrocarbons and other wellbore fluids to surface), the ability to estimate this downhole pump condition from the measured surface pressure has significant economic implications for an oil producing entity in the field.

[0076] In embodiments, the tubing pressure P observed at the surface can be time-synchronized with measurements of the position of the plunger in the downhole pump by performing a best-estimate matching of the tubing pressure cycle to the pumping cycle. Such time-synchronization is used as a reference to interpret the tubing pressure measurements in relation to the position of the plunger in the pumping cycle. In this manner, a fault or anomaly in pump operation is naturally exhibited in the measured tubing pressure P. Since the exact position of the plunger can be difficult to determine due to the pump's position downhole, the position of the head of the pump jack Y at surface can be used instead. As discussed below, the measured pressure inflections are a more reliable means to assess pump operation.

[0077] Figs.
3A to 3D respectively illustrate time series graphs of pump head position Y, pump position/displacement, pump discharge pressure Pd, and surface tubing pressure P at each stage of the process of converting energy exerted at the surface by the pump jack 4 into the energy returning to surface as flowing oil (and other fluids) and pressure P. The position Y of the head of the pump jack over time is depicted at Fig. 3A. Fig. 3B shows the position of the pump plunger over time. It may be similar to the movement of the pump jack head Y at surface, but slightly changed as the motion of the pump jack head is transferred through many mechanical components of the rod string 6 before reaching the downhole pump 10. The motion of the pump plunger is converted into a discharge pressure Pd. Fig. 3C depicts a time series graph of the discharge pressure Pd that emanates from the pump 10 towards the surface, and exhibits a transformation in the wave form when compared to the motion of the plunger. Fig. 3D depicts a time series graph of the surface tubing pressure.
The period of the waveforms depicting pump jack head position Y and pump plunger movement, and the period of the waveforms showing pump discharge and surface pressure, are substantially the same. Yet, the pressure pattern demonstrates changes in the waveform.

[0078] An examination of the primary energy components entering the downhole pump 10 (i.e. force and displacement) and leaving the pump 10 (i.e.
pressure) demonstrates a cyclical pattern for each of the components, as illustrated in Figs. 4A and 4B.

[0079] With reference to Fig. 4A, when the force applied to the pump 10 from the pump jack 4 is plotted as a function of time, it can be seen that it alternates between a tensile (positive) force and a compressive (negative) force.
The force applied to the pump 10 changes between tension and compression when the plunger 12 changes its direction of movement, the force being a tensile force when the plunger 12 is pulled uphole, and a compressive force when the plunger 12 is pushed downhole. However, after the transition from tension to compression and vice versa, the force applied to the pump 10 is relatively constant, as illustrated by the relatively discrete changes in the force curve in Fig.
4A as compared to the plunger position curve, which has a more sinusoidal shape. In other words, the force alternates between two relatively constant force levels over a pump cycle. This is well described in "Evolution of the Downhole Card As a Diagnostic Tool for Rod Pumping" by Dr. S. G. Gibbs, Ph. D. Thus, the graph of plunger position vs. time contains much of the pertinent information regarding energy input into the downhole pump 10.

[0080]
Looking next at the flow component, with reference to Fig. 4B, it is understood that fluid flow to surface only occurs during the upstroke of the pump 10, when the traveling valve 14 is closed and the plunger 12 is moving towards surface. As a result, the flow rate coming out of the downhole pump 10 alternates between approximately 100% flow rate and 0% flow rate. The flow rate from the downhole pump 10 can be estimated from the following equation:
Q = A v where Q = Flow rate coming out of the downhole pump;
A = cross-sectional area of the pump; and v = Displacement speed of the pump plunger.

Displacement speed v can be calculated from the plunger displacement divided by time. Since the cross-sectional area A of the pump 10 is a constant, flow Q

and displacement speed v are proportional and will have a similar wave form.

[0081] The graph in Fig. 4B shows pressure and displacement speed (which is proportional to flow) generated by the downhole pump as a function of time. It demonstrates that, while the displacement pressure Pd is rising, the displacement speed v, and therefore flow, also rises from 0% to 100%.
Therefore, the displacement of the plunger 12 and the discharge pressure Pd have a close relationship, and contain details of the operation of the downhole pump 10 as it transforms input energy into output energy. In other words, the discharge pressure Pd from the downhole pump 10 contains functional details about the operation of the pump 10.

[0082] As discussed above, variations in downhole pressure Pd travel to the surface at the speed of sound and are measurable as surface tubing pressure P. Therefore, tubing pressure P can be measured in place of Pd to evaluate the operation of the downhole pump 10 and diagnose potential or present problems thereof.
Fault Detection Using Surface Tubing Pressure

[0083]
Examples are provided herein with respect to how surface tubing pressure P can be used to analyze the performance of a downhole pump 10, and detect the presence of faults/malfunctions thereof. In normal pump operation, with reference to Figs. 5A to 5D, the pump 10 is running at 100% efficiency.
The barrel 16 of the pump is filling fully during each cycle, little to no gas enters into the pump, and the standing and travelling valves 14,18 are functioning normally.
With reference to Fig. 6A, actual surface tubing pressure measurements P over time are shown, as acquired by a pressure measurement device 30 located on the tubing string 8 at surface. During normal pump operation, the curve of surface tubing pressure vs. time appears to take on a generally sinusoidal pattern. Fig. 6B shows a best-fit model of a single-frequency sinusoid approximating the pressure measurements and another single-frequency sinusoid approximating the position of the pump plunger. The sinusoid can be described as Y = A sin (wt +B), where Y is the position of the plunger, A is the amplification constant, w is the cycle per minute (angular velocity), and B is the angular offset to match the phase of the curve with the pressure profile.

[0084] Fig.
5A depicts stage A of the pump cycle, wherein the plunger 12 is moving uphole towards the surface and nearing its highest point with relative to the stationary pump barrel 16. During stage A of the pump cycle, the plunger is pulling away from the barrel 16 and the travelling valve 14 of the plunger is closed due to the weight of the accumulated fluid column F thereabove and the negative pressure created in the pump barrel chamber 16 by the plunger 12 pulling away therefrom. As the plunger 12 moves uphole within the barrel 16, the negative pressure created in the pump barrel chamber causes the standing valve 14 to open, allowing fresh fluid from the wellbore and hydrocarbon reservoir to enter the barrel chamber 16. The pressure increase at surface, caused by the closing of the travelling valve 14 and uphole movement of the plunger 12, is shown in Fig. 6B in the section labelled A.

[0085] Fig. 5B
depicts stage B of the pump cycle, which is the point the plunger 12 changes its direction and begins to move downhole towards the standing valve 18. During stage B, with fluid being compressed between the descending travelling valve 14 and the fixed standing valve 18, the standing valve 18 closes due to the increased pressure inside the barrel chamber 16.
This increased pressure in the barrel chamber 16 also opens the traveling valve 14 of the plunger, which in turn causes the pressure inside the barrel chamber to equalize with the pressure of the accumulated fluid column F above the travelling valve 14. The opening of the travelling valve 14 causes a reduction in pressure in the production tubing 8, shown in Fig. 6B in the section labelled B.

[0086] At stage C, as shown in Fig. 5C, the plunger 12 is approaching its lowest position before changing the direction to begin the upstroke. The pressure in the production tubing continues to decrease, as shown in Fig. 6B in the section labelled C.

[0087] At stage D, as shown in Fig. 5D, the plunger 12 has changed direction and has begun to travel uphole. As the plunger 12 ascends, the volume in the barrel 16 increases and the pressure therein decreases. The traveling valve 14 closes due to the decreasing pressure inside the barrel chamber 16 and the weight of the accumulated fluid column F in the production tubing 8 above the traveling valve 14. The standing valve 18 opens as the chamber pressure decreases and reservoir fluid enters the barrel chamber 16 therethrough. The pressure in the tubing string 8 begins to increase due to the travelling valve being closed, the uphole movement of the plunger 12, and the displacement of the accumulated fluid F from the wellhead, as shown in Fig. 6B in the section labelled D.

[0088] Based on the typical behavior above, a pump malfunction in the form of fluid pounding/partial pump fillage, standing valve failure, travelling valve failure, and gas interference produces noticeable deviations in the measured surface tubing pressure P from the expected pressure curve.

[0089] In the case of partial pump fillage, also known as fluid pounding, the plunger 12 moves uphole too quickly and there is not enough time during each upward stroke for the barrel 16 of the pump to fill completely. This results in a barrel chamber that is only partially full. Partial fillage can also occur when there is a significant amount of gas produced together with oil. During the transition from stage A to B, the traveling valve 14 opens and the fluid column F
thereabove rushes into the partially filled barrel chamber 16 to fill the space occupied by gas, which results in a sudden drop in pressure during the stage transition. This sudden pressure change travels up the accumulated fluid column F to surface and is seen in measurements of surface tubing pressure P.

[0090] Fig.
7A illustrates the measured surface tubing pressure for such a case. Fig. 7B depicts the measured surface tubing pressure and a sinusoidal waveform approximating pump plunger position overlaid thereover. As indicated by the circled sections of Fig. 7B, partial pump fillage is characterized by a more rapid drop in pressure between stages A and B compared to the pressure curve for normal pump operation. That is, there is a rapid drop in pressure between the upstroke section and downstroke section of the pump cycle as opposed to the smooth transition from increasing pressure during the upstroke section to decreasing pressure during the downstroke section expected during normal pump operation. From Figs. 7A and 7B, it is apparent that partial fillage may occur during some, but not every, pump cycle, as shown by the measured surface tubing pressure P decreasing in the expected manner in some cycles.
Therefore, by measuring surface tubing pressure P, even incipient conditions causing partial fillage can be detected, thus providing an early warning and ample time for the operator or pump jack controller to take remedial action, such as slowing the pump cycle rate.

[0091] Fig.
7C shows a more dramatic case of partial pump fillage, wherein the pressure drop after the plunger 12 has reached its highest position is more pronounced relative to that shown in Figs. 7A and 7B.

[0092] Surface tubing pressure measurements may also be used to detect leakage in the standing and/or travelling valves. With reference to Fig. 8A, a leak in the standing valve 14 is characterized by the surface tubing pressure P not dropping to the expected minimum, or within an expected low pressure range, during a downstroke segment of the pump cycle, defined as the period of the pump cycle after the pump plunger 12 has reached its highest position 12a and is moving toward its lowest position 12b. The surface tubing pressure P does not reach the expected minimum as the pressure in the barrel chamber 16 is not high enough (due to the leaking standing valve 18) to fully open the travelling valve 14 to permit the pressure in the fluid column F thereabove to equalize with the pressure therebelow between stages B and C. Fig. 8B depicts a graph of surface tubing pressure P over time in the case of a standing valve leak, with anomalous regions where surface tubing pressure P does not drop to expected levels circled.

[0093] With reference to Fig. 9A, a leak in the travelling valve 18 is characterized by the surface tubing pressure P not rising to the expected maximum, or within an expected high pressure range, during an upstroke section if the pump cycle, defined as the period after the pump plunger 12 has reached its lowest position 12b and is moving toward its highest position 12a. The surface tubing pressure P does not reach the expected maximum as pressure in the tubing string 8 above the travelling valve 14 continually equalizes with the lower pressure therebelow, even between stages D and A when pressure increases in normal operation. Fig. 9B depicts a graph of surface tubing pressure over time in the case of a travelling valve leak.

[0094]
Another problem that can arise during pumping operations is gas interference, which is when gas bubbles are quickly dissolved into liquid phase based on the surrounding pressure condition. Fig. 10A depicts actual measured surface tubing pressure P in a case of gas interference. Fig. 10B shows the best-fit single-frequency sinusoid of pump plunger position superimposed over the measured tubing pressure P in a gas interference case, which illustrates that the surface tubing pressure curve when gas interference is present differs significantly from the normal pressure curve. The presence of gas bubbles in the fluid impedes the pumping action, and much of the energy input into the system is wasted compressing and decompressing the gas in the liquid matrix.

[0095] Figs.
10C and 10D respectively depict gas interference in a downhole pump 10, and a graph of the measured surface tubing pressure P and estimated pump position over time. As can be seen from Fig. 10D, the pressure remains flat for a significant period of time at the minimum pressure.
Additionally, the peak-to-peak tubing pressure is significantly lower than the expected peak-to-peak tubing pressure for this particular case. While peak-to-peak surface tubing pressure can vary widely from wellbore to wellbore, an operator would typically know what the expected peak-to-peak tubing pressure should be for normal pump operation. Further, compared to the pump cycle as shown by the estimated pump position, the pressure only elevated for 30% of the pump cycle, while for the remaining 70% of the cycle the pressure remains substantially flat or constant. Finally, the falling edge of the pressure curve is more gradual than the rising edge of the pressure curve.

[0096] With reference to Fig. 10C the effect of gas interference on the operation of the downhole pump is described herebelow. At stage A', the pump plunger 12 has started moving upward. The traveling valve 14 is closed and the standing valve 18 has just opened. Gas G is entrained in the fluid column F
above the traveling valve 14. The upward motion of the plunger 12 begins to increase the tubing pressure as per normal operation. However, the tubing pressure P near surface does not rise as the entrained gas G is collapsing back into fluid column F due to the rising tubing pressure.

[0097] At stage B', the plunger 12 is moving uphole and continues to increase the tubing pressure. However, energy continues to be absorbed to collapse the entrained gas G into the liquid matrix in the fluid column F, and no significant increase in surface tubing pressure P is observed. At this stage, the pump jack 4 sees a gradual increase in load instead of the usual sudden increase to the maximum tensile load. This is due to the buoyancy of the plunger 12 and rod string 6 due to the entrained gas bubbles in the fluid column F, which causes a gradual increase in the load on the rod string 6. This appears as a rounded corner in a traditional pump dynamometer card.

[0098] At stage C', as the gas bubbles G in the fluid column F collapse and are dissolved therein, the bulk modulus of the fluid increases and the fluid begins to behave more like liquid rather than gas. As a result, the "spongy"
behavior of the gas-containing fluid column F diminishes. In other words, a sufficient amount of gas bubbles have been collapsed/dissolved into the fluid column F, and the fluid begins to transfer the rise in pressure inside tubing string.
At this stage, the surface tubing pressure P begins rising corresponding to the upward movement of the plunger 12. The pump jack 4 sees the full weight of the liquid column F at this stage, i.e. the tension force on the pump jack is at maximum.

[0099] At stage D', a sudden jump in surface tubing pressure P continuing to maximum pressure suggests that the fluid column F between the traveling valve 14 and surface is beginning to behave more like a liquid. However, as the plunger 12 rises, the standing valve 14 opens and the suction pressure caused by the rising plunger 12 will draw in liquid from reservoir mixed with additional gas. The lower pressure caused by suction will induce the emergence of more gas G in the liquid matrix. The tensile force on the sucker rod string 6 stays at the maximum, as the rod string 6 is bearing the carrying full weight of the fluid column F.

[0100] At stage E', the plunger 12 begins to descend. The travelling valve 14 may open with a slight delay due to the gas-containing liquid in the barrel chamber 16. The opening of the traveling valve 14 is normally followed by a sudden loss in the force measurement on the rod string 6. However, the measured force does not rapidly fall to the minimum, as in normal pump operations, but instead gradually decreases to the lowest level as the plunger travels 12 downward. The lowering of the plunger 12 reduces pressure in the tubing string 8 and the dissolved gas G in the fluid column F will reemerge.
This results in a slowed pressure drop inside the tubing 8. Bubbles entrained in the fluid column F provide gas lift and maintains surface tubing pressure P at an elevated level. If the surface tubing pressure P is decreasing slowly, this is indicative of more gas bubbles G inside the liquid matrix of the fluid column, and consequently more buoyancy acting to slow the decrease in surface tubing pressure P.

[0101] At stage F', the plunger 12 continues moving downward. As fluid from below the traveling valve 14 flows above the traveling valve, the traveling valve opens more quickly. The decrease in surface tubing pressure P stops relatively quickly and then stays flat as opposed to decreasing further as in normal pumping operation. This sudden pressure stability can be explained by additional dissolved gas reemerging in the fluid column F. Since the plunger 12 is still continuing to move downward, the flat surface tubing pressure indicates that the pressure in the column F is decreasing, but the reemerging gas G is compensating for the pressure drop and maintaining tubing pressure P at about a constant level. Gas lift-like behavior becomes more prominent if the fluid column F contains a larger percentage volume of gas. As the gas content in the pump chamber 16 increases, it begins to show decreasing fillage in the form of reduced maximum pressure and a more gradual reduction of pressure to the minimum pressure of the pump cycle.

[0102] At stage G', near the end of the downstroke, even though the plunger 12 is still descending, an equilibrium has been reached between the decreasing tubing pressure P due to the downhole movement of the plunger 12 and the increasing pressure from the reemerging gas G in the fluid column F.
Thus, the measured surface tubing pressure P remains flat. The tensile load on the sucker rods 6 has reached the minimum level.
Pump Pressure Card

[0103] In embodiments, a Pump Pressure Card (PPC) can be generated by plotting surface tubing pressure vs. plunger amplitude / plunger position.
The PPC can be created by time-synchronized measurements of surface tubing pressure P and plunger position. For convenience, the position of the pump jack head Y can be used in place of the downhole plunger position. The stretching and shrinking of the rod string 6 during the pump cycle creates a slight deviation in the actual downhole pump position compared to the position of the pump jack head Y. However, this deviation is cyclical and repeatable. Therefore, the relationship between the surface tubing pressure P and pump jack head position Y at a given point in time is usable as a reference to identify anomalous pump operation.

[0104] Figs.
5E and 6C show a PPC for a downhole pump operating normally. The relationship between the surface tubing pressure P and the estimated plunger position will, in many cases, tend to show a concave, upward curve. This indicates that the pressure response slightly lags behind the plunger movements in proportion. This may be due to the fact that the beginning and the end of the pressure cycle was matched to the beginning and end of the motion cycle for more convenient analysis of the surface tubing pressure compared to the estimated position of the pump plunger at the same part of the pump cycle.

This is an arbitrary choice and may not be exact, but the approximate pump position information is helpful in assessing the operation of the downhole pump.
Note that the counter-clockwise rotational pattern shown in the figure is due to the slight time lag of pressure behind plunger position, which is typically the expected case.

[0105] Stage A of the pump cycle is shown in the figure at the upper right end of the curve, where the plunger 12 is approaching its highest position and the surface tubing pressure P is nearing its peak. Stage B shows the tubing pressure and plunger position both decreasing towards Stage C. Stage C is located at the bottom left of the curve, where the plunger 12 is approaching its lowest position and surface tubing pressure P is nearing its minimum point.
Stage D shows the plunger 12 reversing direction and beginning to move uphole, while tubing pressure P gradually increases.

[0106] As shown in Fig. 7D the PPC for a case of partial pump fillage shows a pressure drop between stages A and B of the pump cycle. Furthermore, using the PPC, the degree to which a downhole pump is filling with each stroke, i.e. pump fillage, can be described as ratio or percentage.

[0107]
Turning to Fig. 7E, a model PPC of a partial fillage scenario is used for the purposes of illustrating how to calculate pump fillage. The progression of pump cycle stages in this the model PPC move clockwise instead of counter clockwise. This is due to the fact that the plunger position is estimated relative to the pressure measurements during the pump cycle. When the peak of the pressure cycle is slightly ahead in time relative to the peak of the plunger position, the stage progression in the PPC proceeds in a clockwise manner.
When the pressure is slightly behind the plunger position in time, the PPC
proceeds in a counter-clockwise fashion.

[0108] As shown in Fig. 7F, a nominal percentage based on the pressure differences between pumping stages observed in the PPC can be used to describe pump fillage. The maximum pressure difference over the course of the pumping cycle is defined as corresponding to 100% fillage. A sudden pressure drop between stages A (the end of the upstroke section of the pump cycle) and B
(the beginning of the downstroke section of the pump cycle) can then be measured against this "100% fillage" pressure difference. The fillage index, or how much the pump has been filled in a given cycle, can be calculated as:
Fillage Index = ((P100% Fillage - EPA-13) / (P100% Fillage)) * 100%
Where:
P100% Fillage = the change in pressure between the bottom of the pump stroke and the top PA_B = the change in pressure between stages A and B of the pump cycle.

[0109] The fillage index yields a value of 100% when the pump barrel 16 is completely filled during the pump cycle. If the index is 0%, then the barrel 16 is empty. Degrees of partial fullness can be indexed by the ratio between the drop in pressure between stages A and B and the 100% fillage pressure. In this manner, measuring surface tubing pressure P not only enables the identification of a partial fillage situation, but the calculation of the fillage index also allows one to determine the urgency of remedial action. In embodiments, the fillage index can be calculated for multiple pump cycles, and an average fillage index can be calculated from the fillage indices. A running average fillage index can also be calculated as subsequent pump cycles are completed and the fillage indices calculated therefrom.

[0110] Turning to Fig. 8C, the PPC for a case of a leaking standing valve 18 is shown. The PPC shows that the tubing pressure P after a subsequent downstroke did not decrease back to the expected minimum between stages B
and C of the pump cycle. While the PPC of Fig. 8C shows decreasing between stages C and D of the pump cycle, in embodiments the measured pressure P
can increase, such that the line for stage D is above that for stage C in the PPC.
This can occur in instances where the standing valve leak is severe such that the pressure in the pump barrel chamber 16 is not high enough to open the travelling valve 14 at all.

[0111] With reference to Fig. 9C, the PPC for a case of a leaking travelling valve is shown. The PPC shows that after the plunger completed the upstroke, the tubing pressure P did not increase to return to the expected maximum between stages D and A of the pump cycle.

[0112] With reference to Fig. 10E, the PPC for a case of gas interference is shown, having a generally hockey stick shape. The PPC shows that the surface tubing pressure P is flat due to the gas lift action of the gas bubbles entrained in the fluid column F. The surface tubing pressure P increases more sharply during the upstroke and decreases more gradually during the downstroke, resulting in the PPC the hockey stick shape.

Hardware

[0113]
Applicant has identified three conditions useful in the determination of measurements of surface tubing pressure P, used to evaluate downhole pump performance. First, the effects of temperature on the measurements of surface tubing pressure P can be minimized or, ideally, negated. Secondly, the pressure measurements are acquired at a sufficiently high rate to accurately capture of the variations in pressure that are typically produced by the regular pumping motion of the pump plunger 12. In other words, the sampling rate of pressure measurement device 30 must be high enough to detect faults or anomalies in the operation of the downhole pump 10. Preferably, the sampling rate for surface tubing pressure P is at least six times faster than the stroke or cycle rate of the pump jack 4. For example, if the cycle rate of the pump jack 4, comprising a downstroke and upstroke, is six strokes per minute or 0.1 Hz (one cycle every ten seconds) then the sampling rate is ideally 0.6 Hz (one sample every 1.67 seconds) or faster.

[0114] As conventional pumps use rod position and force, pressure sensors or gauges at surface are typically not directed to diagnostic rates of sampling, typically in the range of 1/15 Hz.

[0115] While a slower pressure sampling rate may be used, the ability to accurately identify faults in the operation of the pump 10 may be compromised.

Thirdly, the resolution of the pressure measurement device 30 must be fine enough to observe the small pressure perturbations that are created by the movement of the plunger 12 and propagate to surface. In most cases, to achieve the required data resolution, use of digital values comprised of more than 16 bits is necessary for digital representation of the pressure measurements.
Preferably, the pressure measurement element of the pressure measurement device used is capable of measuring pressure in increments of 1/220 psi, from 0-1000 psi.

[0116] With respect to the first condition, conventional pressure sensors are typically susceptible to drift over time due to temperature fluctuations.
Therefore, it is desirable to use a pressure measurement device 30 that can be calibrated to account for temperature fluctuations. The effect of temperature on the temperature measurements can be predetermined for each pressure measurement device 30, such that the pressure measurements can be corrected to account for the effect of temperature. For example, the pressure measurement device 30 can be operated at various known temperatures to produce a 3D curve of the output measurement from the pressure measurement device in response to a known applied pressure and temperature. The 3D curve can then be used to create a lookup table for converting the pressure output by the pressure measurement device to the actual pressure applied to the device, using the known temperature at or adjacent the point of measurement. In embodiments, this temperature-correction of pressure measurements can be performed automatically by the pressure measurement devices 30 or by a processor 34 that receives the pressure measurements from the pressure measurement devices 30.

[0117] With respect to the second condition, the sampling rate of conventional pressure measurement devices is about once every 15 seconds.
This is due to the Modbus SCADA protocol predominantly used in oil and gas production operations, which uses a 16-bit register for reading and writing data.
The ubiquitous use of the Modbus protocol has discouraged the use of pressure measurement devices having a larger register and capable of sampling surface tubing pressure P at the sampling rates required to obtain a surface tubing pressure dataset that enables the evaluation of downhole pump operations. The cycle speed of a pump jack 4 is typically 3-10 cycles/min. As discussed above, the surface tubing pressure sampling rate is preferably at least six times the cycle rate. Thus, to be capable of sampling surface tubing pressure P at a sufficient rate for the fastest typical pump jack cycling rates, pressure measurement devices 30 used for evaluating pump operations are preferably capable of sampling surface tubing pressure P at a rate of 60 samples/min, or sample/s.

[0118] The use of a pressure measurement device 30 and communications protocol capable of sampling speeds sufficient for monitoring surface tubing pressure for the purposes of analyzing donwhole pump operations is required to implement the method described herein. Such a communications protocol and associated communications device is described in US Patent Application No. 62/402,375 to Ito, and US Patent Application No. 15/718,766 to Ito. Of course, other communications protocols may be used, so long as they are capable of the required sampling rates.

[0119] With respect to the third condition, it is desirable to use a pressure measurement device capable of measuring pressure in at least 1/220 psi increment from 0-1000 psi. Piezoelectric pressure sensors using silicon crystal diaphragm transducers are capable of providing such resolution. For example, suitable pressure measurement devices using silicon crystal transducers are described in "All-fiber high-sensitivity pressure sensor with 5i02 diaphragm"
by Donlagic and Cibula, Optics Letters, Vol. 30, Issue 16, pp. 2071-2073 (2005), "Nano silica diaphragm in-fiber cavity for gas pressure measurement" by Wang et al., Scientific Reports 7, 787 (2017), and "Fabrication and Characterization of a SiC/5i02/Si Piezoresistive Pressure Sensor" by Fraga et al., Procedia Engineering 5 (2010) 609-612. In embodiments, the silicon diaphragm transducers use single-crystal silicon diaphragms, as such transducers are less likely to experience drift in pressure measurements over time due to temperature fluctuations.
System

[0120] With reference to Figs. 2B and 11, an embodiment of a system for measuring surface tubing pressure P comprises at least one pressure measuring device 30, such as a pressure sensor, positioned on the tubing string 8 of the pump jack system 2 and configured to acquire pressure measurements P
therefrom. At least one temperature sensor 32 can also be located adjacent the pressure sensor 30 to acquire temperature measurements in order to temperature-correct the pressure measurements acquired by the pressure sensor 30. In embodiments, temperature measurements can be obtained directly from the data acquired by the pressure sensor. Preferably, for more accurate temperature-correction of the pressure measurements, the temperature sensor 30 is configured to obtain temperature measurements from the fluid in the tubing string 8 adjacent the pressure sensor 30.

[0121] The pressure and temperature sensors 30,32 can transmit the acquired pressure and temperature measurements to a processor 34 configured to analyze said measurements and detect the presence of fault conditions with respect to the operation of the downhole pump 10. For example, the processor 34 can be a pump jack controller located on-site. In some embodiments, the pressure and temperature sensors 30,32 can be configured to convert the acquired pressure and temperature measurements P,T to a digital format before transmitting them to the processor 34.

[0122] In embodiments, the processor 34 can also be configured to correct the acquired pressure measurements P for variations due to temperature T by referencing a lookup table for the pressure measurement device 30 to determine the corrected pressure measurement according to the acquired pressure and temperature measurements.

[0123] In other embodiments, the sensors 30,32 can first transmit the pressure and temperature measurements to a data communications device 36, which relays the measurements to the processor 34. In embodiments, the processor 34 is located off-site, and the communications device 36 is configured to send the measurements to the processor 34 via a transmission line, or through a wireless communication network 38, such as a cellular network, Wi-Fi, Bluetooth, the Internet, etc. The processor 34 can be operatively connected to a machine-readable storage medium containing instructions for processing and analyzing the received pressure and temperature measurements to detect the presence of fault conditions in the operation of the pump according to the method described above.

[0124] In embodiments, the analysis of the pressure and temperatures measurements P,T can be performed at the pressure measurement device 30 or at the communications device 36.

[0125] To reduce the power consumption of the system, the processor 34 can be configured to maintain the sampling rate at which the pressure sensors 30 obtain surface tubing pressure measurements P at a low sampling rate, for example at 6x the pump cycle rate, when pressure measurements P indicate that the pump 10 is functioning normally. The processor 34 can increase the sampling rate when one or more fault conditions are detected, for example to a high sampling rate of 15x the pump cycle rate. In this manner, system power is conserved until there is a need to acquire more data regarding the operation of the pump 10 for diagnostic purposes. As one of skill in the art would understand, pressure sensors 30 are not necessarily limited to operating at a low and high sampling rate, and the sampling rate can be scaled as needed to obtain more or less data regarding the operation of the pump 10.

Claims (24)

WE CLAIM:

1. A method of operating a reciprocating downhole pump located in a wellbore and fluidly connected to equipment at surface via a tubing string for flowing well fluids to the surface, comprising:
locating one or more pressure sensors on the tubing string at surface;
obtaining surface tubing pressure measurements of the tubing string at surface at a sampling rate using the one or more pressure sensors;
analyzing the pressure measurements indicative of pump performance;
identifying the existence of one or more fault conditions from the pressure measurements; and reporting the existence of the fault condition.

2. The method of claim 1, further comprising:
predetermining the effect of temperature on the pressure measurements obtained for each of the one or more sensors;
correcting the pressure measurements obtained from the one or more pressure sensors to account for the effect of temperature thereon.

3. The method of claim 1 or 2, further comprising locating one or more temperature sensors on the tubing string at surface, obtaining temperature measurements using the one or more temperature sensors, and correcting the pressure measurements obtained from the one or more pressure sensors using the temperature measurements obtained from the one or more temperature sensors.

4. The method of claim 3, wherein the one or more temperature sensors are positioned such that the temperature measurements are representative of the fluid adjacent the one or more pressure sensors.

5. The method of any one of claims 1 to 4, wherein the sampling rate of the pressure measurements is at least six times a cycle rate of the downhole pump.

6. The method of any one of claims 1 to 4, wherein the sampling rate of the pressure measurements is about 15 times the cycle rate of the downhole pump.

7. The method of any one of claims 1 to 6, wherein the step of obtaining pressure measurements further comprises converting the pressure measurements from analog data to digital data at the one or more pressure sensors.

8. The method of any one of claims 1 to 7, wherein the step of analyzing the pressure measurements further comprises generating a waveform of the pressure measurements over time.

9. The method of any one of claims 1 to 8, wherein the one or more fault conditions comprises fluid pounding, leaking standing valve, leaking travelling valve, and gas interference.

10. The method of any one of claims 1 to 9, wherein the step of automatically reporting the existence of the fault condition further comprises:
reporting a fluid pounding fault condition if the pressure measurements drop rapidly after one or more pressure peaks of the pressure measurements;
reporting a leaking standing valve fault condition if the pressure measurements are not within an expected low pressure range during a downstroke time segment of the pressure measurements;

reporting a leaking travelling valve fault condition if the pressure measurements are not within an expected high pressure range during an upstroke time segment of the pressure measurements; and reporting a gas interference fault condition if the pressure measurements are not within an expected low pressure range and are substantially constant during a downstroke time segment of the pressure measurements.

11. The method of any one of claims 1 to 10, wherein the step of obtaining pressure measurements further comprises increasing the sampling rate if the existence of one or more fault conditions is identified.

12. The method of any one of claims 1 to 11, further comprising:
establishing position measurements related to a position of the reciprocating downhole pump; and generating a pump pressure card using the pressure measurements and position measurements.

13. The method of claim 12, wherein the equipment at surface comprises a pump jack, and the position measurements are established from a position of the pump jack.

14. The method of claim 12, wherein the equipment at surface comprises a rod string connecting a pump jack to the downhole pump, wherein the position measurements are established from a position of the rod string.

15. The method of any one of claims 1 to 14 further comprising calculating a pump fillage index from a peak-to-peak pressure difference of the pressure measurements over a pump cycle and a rapid pressure drop difference between an end of an upstroke time segment of the pump cycle and a beginning of a downstroke time segment of the pump cycle.

16. The method of any one of claims 1 to 14 further comprising:
establishing a peak-to-peak pressure difference of a pump cycle from the pressure measurements;
establishing a rapid upstroke and downstroke pressure drop difference between an upstroke time segment and downstroke time segment of the pressure measurements;
establishing a running average of a difference between an upstroke time segment and downstroke time segment of the pressure measurements for multiple pump cycles; and calculating a pump fillage index from the peak-to-peak pressure difference and the rapid upstroke and down stoke pressure drop difference.

17. A system for determining performance of a reciprocating downhole pump located in a wellbore and fluidly connected to equipment at surface configured to receive fluid delivered therefrom via a tubing string, comprising:
one or more pressure sensors positioned to obtain pressure measurements from within the tubing string at surface; and a processor configured to receive the pressure measurements from the one or more pressure sensors for sampling pressure data from the one or more pressure sensors at a sampling rate.

18. The system of claim 17, wherein the sampling rate is at least six times a cycle rate of the downhole pump.

19. The system of claim 17, wherein the sampling rate is at least 15 times a cycle rate of the downhole pump.

20. The system of any one of claims 17 to 19, further comprising a communications device operatively connected to the one or more pressure sensors and configured to receive the pressure measurements from the one or more pressure sensors and send said measurements to the processor.

21. The system of any one of claims 17 to 20, further comprising one or more temperature sensors positioned to obtain temperature measurements of the fluid flowing within the tubing string at surface.

22. The system of any one of claims 17 to 21, wherein the one or more pressure sensors are silicon crystal piezoelectric sensors.

23. The system of any one of claims 17 to 22, wherein the one or more pressure sensors are single crystal silicon crystal piezoelectric sensors.

24. The system of any one of claims 17 to 23, wherein the one or more pressure sensors are capable of obtaining pressure measurements in increments of 1/220 from 0 to 1000 psi.